When drilling for oil and gas, a wellbore or borehole of an oil or gas well is typically drilled from surface to a first depth and lined with a steel casing. The casing is located in the wellbore extending from a wellhead provided at surface or seabed level, and is then cemented in place. Following testing and other downhole procedures, the borehole is extended to a second depth and a further section of smaller diameter casing is installed and cemented in place. This process is repeated as necessary until the borehole has been extended to a location where it intersects a producing formation. Alternatively, a final section of tubing known as a liner may be located in the wellbore, extending from the lowermost casing section or casing ‘shoe’ to the producing formation, and is also cemented in place. The well is then completed by locating a string of production tubing extending from surface through the casing/liner to the producing formation. Well fluids are then recovered to surface through the production tubing.
However, before the well can be completed and well fluids recovered to surface, it is necessary to clean the lined wellbore and replace the fluids present in the wellbore with a completion fluid such as brine. The cleaning process serves, inter alia; to remove solids adhered to the wall of the casing or liner; to circulate residual drilling mud and other fluids out of the wellbore; and to filter out solids present in the wellbore fluid. Much of the solids present in the wellbore are found on the surface of the casing/liner, and may be rust particles and metal chips or scrapings originating from equipment used in the well and from the casing/liner itself.
For this purpose, well cleaning equipment is well known and comes in a variety of different forms, including casing scrapers, brushes and circulation fluid tools. Such equipment is used to free the well tubing from debris particles such as cement lumps, rocks, caked mud, and so on.
It is now common practice to run dedicated well cleaning apparatus after cementing the liner and prior to completion. Tools have also been provided in the art for incorporation in drill and the like work strings which are intended to perform a cleaning operation in wellbore completions.
During the extraction of conventional cleaning tools from the well, additional debris can be dislodged, such as from the wall of the casing, thereby undoing much of the cleaning work already performed.
The operation of such a tool can be understood from GB 2,335,687 (see FIG. 1) which describes a cleaning tool 1 for cleaning a casing 2, the cleaning tool 1 including a body, diversion means for diverting well fluid passing the tool 1 between a mandrel 4 and the exterior of the tool 1, and a filtration means comprising a filter 6 for filtering debris particles from at least some of the well fluid. When the cleaning tool 1 is pulled out of the wellbore, any dislodged debris falls into a diverter cup 5 at the top of the tool 1, and is diverted via bores 8 into a chamber 9 bounded by the mandrel 4 on the inside, the filter 6 on the outside and a one-way valve 12 at the lower end. Liquids can pass directly out of the filter 6, leaving the debris trapped in the chamber 9. For further details of the cleaning tool and the flowpaths operating when the tool is reciprocated, i.e. run in hole (RIH) and pulled out of hole (POH), see GB 2,335,687 the contents of which are hereby incorporated by reference.
FIG. 2 shows an enlarged view of the upper end of the FIG. 1 tool, which is only shown schematically in FIG. 1.
The diverter cup 5 is a resilient swab cup, with a concave-up orientation. The diverter cup 5 is mounted to the mandrel 4 via a tubular body 20, which is located concentrically around the mandrel 4 and which is connected to the mandrel 4 via screws 22. The heads of the screws 22 are received in an outer tubular 24, which overlies the lower end of the tubular body 20. The upper end of the filter 6 is received and supported between the outer tubular 24 and the tubular body 20.
The diverter cup 5 has a diverter cup housing 26 which encloses the lower end of the diverter cup 5 and mounts the diverter cup 5 to the tubular body 20 by retaining the lower end of the diverter cup 5 between itself and the tubular body 20. The diverter cup housing 26 has an inner diameter that matches the local outer diameter of the tubular body 20.
The tubular body 20 has an increased diameter portion 30, defining a limit stop 32 on a lower face thereof. The limit stop 32 is configured to engage the diverter cup housing 26, indirectly, via a bearing 34. An additional bearing 36 is located underneath the diverter cup housing 26, between the diverter cup housing 26 and the outer tubular 24.
The diverter cup 5 has a protective cap 28 on its upper end. The protective cap 28 is not connected to the tubular body 20 and does not mount the upper end of the diverter cap 5 on the tubular body 20. Instead, there is a flowpath around the cap 28, between the diverter cup 5 and the tubular body 20, to the inside of the tubular body 20 via bores 38 in the tubular body 20.
Whilst such a tool has gained wide approval in the field, it is considered that further improvements can be made.
It has been noted that when the downhole string is pulled out of the hole. The diverter cup 5 is effectively pushed out of the hole from its lower end, by the outer tubular 24 pushing on the bearing 36, pushing on the diverter cup housing 26, pushing on the lower end of the diverter cup 5. This pushing together with the “swiping” effect by contact within the hole causes the diverter cup 5 to “squat” or shorten to a wider profile, making it much more prone to damage by catching or snagging on any ledges in the hole. This means that in some cases the use of the tool has to be interrupted or delayed to return the tool to the workshop to restore operational capability. Whilst this is easily accomplished the associated downtime due to the re-dressing work and time lost in run-in and pullout represents a significant cost to the industry.